Natural gas consists primarily of saturated hydrocarbon components such as methane, ethane, propane, butane, and heavier hydrocarbons. Natural gas typically contains about 60-100 mole percent methane, the balance being primarily heavier alkanes. Alkanes of increasing carbon number are normally present in decreasing amounts. Carbon dioxide, hydrogen sulfide, nitrogen, and other gases may also be present.
There are many reasons to separate the higher alkanes known as natural gas liquids (NGL) from natural gas to provide a methane-rich natural gas stream. One such reason is to meet pipeline specifications or liquefied natural gas (LNG) specification for heating value, dew point, and condensation. Some stationary internal combustion engines, such as natural gas engines, are designed to operate for optimal efficiency within a specific BTU range and may require higher maintenance costs, higher operating temperatures, reduced equipment life expectancy, and/or generate increased pollution if operated at higher BTUs.
Additionally, it may be financially desirable to recover natural gas liquids from natural gas. NGLs including ethane, propane, butane, and lesser amounts of other heavy hydrocarbons may be used as petrochemical feedstocks where they have a higher value as compared to their value as a fuel gas component.
In other instances, gas is co-produced with oil and the concentrations of NGLs can be very high ranging from a fraction of a percent of the gas flow to tens of percent. This gas can be of poor quality due to high levels of carbon dioxide, nitrogen, and other components. The gas flow rate can be small and often it is not economical to bring a pipeline to an isolated location where natural gas is produced, such gas is sometimes referred to as stranded gas. In these instances, the best alternative is to flare the gas. However, flaring of gas high in NGLs may have a significant negative impact on the environment, accounting for a significant amount of CO2 and heat that is injected into the atmosphere. In addition to capturing value for separated NGLs that can be stored in a tank for later transportation and sale, it would be environmentally advantageous to remove the NGLs from the gas to reduce the amount of CO2 and heat uselessly released into the environment.
There are two basic steps for the separation of natural gas liquids from a natural gas stream. First, the liquids must be extracted from the natural gas. Second, these natural gas liquids must be separated themselves, down to their base components. There are two principle techniques for removing NGLs from the natural gas stream are the oil absorption method and the cryogenic expander process. These two processes account for around 90 percent of total natural gas liquids production.
The absorption method of NGL extraction utilizes an adsorbing oil which has an affinity for NGLs. Before the oil has picked up any NGLs, it is termed “lean” absorption oil. As the natural gas is passed through an absorption tower, it is brought into contact with the absorption oil which soaks up a high proportion of the NGLs. The “rich” absorption oil, now containing NGLs, exits the absorption tower through the bottom. It is now a mixture of absorption oil, propane, butanes, pentanes, and other heavier hydrocarbons. The rich oil is fed into lean oil stills, where the mixture is heated to a temperature above the boiling point of the NGLs, but below that of the oil. This process allows for the recovery of around 75 percent of butanes, and 85 to 90 percent of pentanes and heavier molecules from the natural gas stream.
Although there are many known adsorption processes, there is always a compromise between high recovery and process simplicity (i.e., low capital investment). Common adsorption technologies focus on removal of hydrocarbons, which works well in non-hydrocarbon rich streams, but is limited in applicability in hydrocarbon continuous streams. Further this technology is not selective for certain molecular size/weight.
Cryogenic processes are also used to extract NGLs from natural gas. While absorption methods can extract almost all of the heavier NGLs, the lighter hydrocarbons, such as ethane, are often more difficult to recover from the natural gas stream. In certain instances, it is economic to simply leave the lighter NGLs in the natural gas stream. However, if it is economic to extract ethane and other lighter hydrocarbons, cryogenic processes are required for high recovery rates. Essentially, cryogenic processes consist of dropping the temperature of the gas stream to around −120 degrees Fahrenheit. There are a number of different ways of chilling the gas to these temperatures, but one of the most effective is known as the turbo expander process. In this process, external refrigerants are used to cool the natural gas stream. Then, an expansion turbine is used to rapidly expand the chilled gases, which causes the temperature to drop significantly. This expansion can take place across a valve as well. This rapid temperature drop caused by the Joule-Thompson effect condenses ethane and other hydrocarbons in the gas stream, while maintaining methane in gaseous form. This process allows for the recovery of about 90 to 95 percent of the ethane originally in the natural gas stream. In addition, the expansion turbine is able to convert some of the energy released when the natural gas stream is expanded into recompressing the gaseous methane effluent, thus saving energy costs associated with extracting ethane. These plants can be called JT plants, refrig plants, or cryo plants which are all variations on the same temperature drop processes.
While reliable, cryogenic systems suffer from a number of shortcomings including high horsepower requirements. Further, such systems require relatively rigorous and expensive maintenance to function properly. Mechanical refrigeration systems also have practical limits with respect to the amount of cold that may be delivered, accordingly, the efficiency and capacity of such systems is limited. The operating window (range of operating conditions the plants can function well within) is a relatively narrow window, requires time to start-up and shut-down effectively, and is quite capitally intensive. As a result these facilities are often used at higher gas flow rates to ensure a more economic cost to treat the system. And if the facility is to be constructed, and can only operate in a narrow range of operating conditions, there are significant upstream treatment systems required to remove CO2 (amine systems), water (glycol dehydration) and sometimes even pre-chilling (propane chillers).
Once NGLs have been removed from the natural gas stream, the mixed stream of different NGLs must be separated out. The process used to accomplish this task is called fractionation. Fractionation works based on the different boiling points of the different hydrocarbons in the NGL stream. Essentially, fractionation occurs in stages consisting of the boiling off of hydrocarbons one by one. By proceeding from the lightest hydrocarbons to the heaviest, it is possible to separate the different NGLs reasonably easily.
Of the various alternative technologies, adsorption process appears to be the most promising. An adsorbent suitable for the separation of NGLs should have high adsorption capacity and selectivity for either olefin or paraffin. Adsorbed component should be able to desorb easily by simple chemical engineering operation such as by increasing the temperature or by reducing the pressure. Conventional adsorbents such as zeolites, activated carbon, activated alumina, silica gels, polymer supported silver chloride, copper-containing resins, and the like known in the prior art which exhibit selectivity for ethylene or propylene suffer from one or more drawbacks such as slow adsorption kinetics, poor adsorption capacity, and/or selectivity. Furthermore, due to ever changing business requirements and demands, it is desirable to have adsorbents exhibiting even higher adsorption capacity, selectivity, and/or reversibility for efficient separation of hydrocarbon gases.
Oilfields are often located in remote locations where power grids have not yet been developed and electrical power is not available. Typically, fuels, such as diesel, to run onsite oilfield equipment need to be transported to such remote locations. While natural gas is often readily available in such remote locations, the use of raw gas is not feasible unless the natural gas liquids have first been removed.
In addition to onsite equipment, equipment associated with the natural gas pipeline (i.e., engines used to pressurize the pipeline) may use raw natural gas as their primary fuel. However, if the heat value of the raw natural gas is high, because of the presence of natural gas liquids, the equipment can require increased maintenance, reduced operational lifetime, and/or produce pollutions such as NOx.
It would be desirable to have an on-site methane-rich natural gas source to drive natural gas powered equipment at, or near wellheads, or associated with pipelines, especially in remote locations.